Hydrocarbon recovery using complex water and carbon dioxide emulsions

ABSTRACT

In one aspect, a method of recovering hydrocarbons from a subterranean zone includes flowing carbon dioxide in a first state into the subterranean zone including hydrocarbons, wherein a density of the carbon dioxide in the first state is greater than a density of carbon dioxide in a gaseous state, and recovering at least a portion of the hydrocarbons in the subterranean zone in response to flowing carbon dioxide in the first state into the subterranean zone.

TECHNICAL FIELD

This disclosure relates to recovery of hydrocarbons from subterraneanzones.

BACKGROUND

Many techniques can be used to recover hydrocarbons from a subterraneanzone. For example, primary techniques can use the natural pressure ofthe subterranean hydrocarbons. Some secondary techniques use injectionsof water or other materials to increase the pressure of the subterraneanhydrocarbons. Beyond primary and secondary techniques, tertiarytechniques (also called “enhanced oil recovery techniques”) can be usedto recover hydrocarbons from subterranean zones. One type of techniqueincludes the injection of materials into the subterranean zone todisplace the hydrocarbons and facilitate recovery.

SUMMARY

This disclosure describes hydrocarbon recovery from subterranean zones.For example, the hydrocarbon recovery can be implemented using complexfluid and gas emulsions.

In some aspects, a method of recovering hydrocarbons from a subterraneanzone includes flowing carbon dioxide in a first state into thesubterranean zone, the carbon dioxide in the first state having adensity greater than that of carbon dioxide in a gaseous state. Themethod also includes recovering at least a portion of the hydrocarbonsin the subterranean zone in response to flowing carbon dioxide in thefirst state into the subterranean zone.

This, and other aspects, can include one or more of the followingfeatures. The carbon dioxide in the first state can include a firstemulsion of water in carbon dioxide. The first emulsion of water incarbon dioxide can be stabilized using first particles that encapsulatethe water. The carbon dioxide can surround the first particles. Thefirst particles can include hydrophobic particles. The hydrophobicparticles can include hydrophobic nano-particles. A concentration of thefirst particles can be between about 0.1% and 0.5% by weight. The firstparticles can include at least one of silica or calcite having ahydrophobic nature. The carbon dioxide in the first state can include asecond emulsion of water in carbon dioxide in water. The second emulsioncan include second particles surrounding the carbon dioxide surroundingthe first particles. The second particles can include hydrophilicparticles. The second emulsion can include second particles surroundingthe carbon dioxide surrounding the first particles. The second particlescan include hydrophilic particles. The second particles can includehydrophilic nano-particles. A concentration of the second particles canbe between about 0.1% and 0.5% by weight. The second particles caninclude at least one of silica or calcite having a hydrophilic nature.The water can surround the second particles. Flowing carbon dioxide inthe first state into the subterranean zone can include flowing carbondioxide into the subterranean zone through a tubular. The method caninclude adding a corrosion inhibitor to the carbon dioxide in the firststate to prevent corrosion of the tubular. The carbon dioxide in thefirst state can include a first emulsion of water in carbon dioxide, anda second emulsion of the first emulsion in water. Adding the corrosioninhibitor can include adding the corrosion inhibitor to the secondemulsion. Flowing the carbon dioxide in the first state into thesubterranean zone can enable producing more hydrocarbons relative toflowing the carbon dioxide in the gaseous state into the subterraneanzone. A viscosity of the carbon dioxide in the first state can begreater than a viscosity of the carbon dioxide in the gaseous state. Thedensity of the carbon dioxide in the first state can be sufficient toovercome a tendency of the carbon dioxide to rise toward a surface.

In some aspects, a method of recovering of recovering hydrocarbons froma subterranean zone includes flowing emulsified carbon dioxide into thesubterranean zone including hydrocarbons, the emulsified carbon dioxidehaving a viscosity that is greater than a viscosity of carbon dioxide ina gaseous state.

This, and other aspects, can include one or more of the followingfeatures. The method can also include recovering at least a portion ofthe hydrocarbons in the subterranean zone in response to flowing theemulsified carbon dioxide into the subterranean zone. The emulsifiedcarbon dioxide can include a first emulsion of water in carbon dioxideand a second emulsion of the first emulsion in water. The first emulsionof water in carbon dioxide can be stabilized using hydrophobicnano-particles that encapsulate the water. The carbon dioxide cansurround the hydrophobic particles. The hydrophobic particles caninclude hydrophobic nano-particles. A concentration of the hydrophobicparticles can be between about 0.1% and 0.5% by weight. The hydrophobicparticles can include at least one of silica or calcite having ahydrophobic nature. The second emulsion can include hydrophilicparticles surrounding the carbon dioxide surrounding the hydrophobicparticles. The hydrophilic particles can include hydrophilicnano-particles. The hydrophilic particles can be between about 0.1% and0.5% by weight. The hydrophilic particles can include at least one ofsilica or calcite having a hydrophilic nature. The water can surroundthe hydrophilic particles. Flowing the emulsified carbon dioxide intothe subterranean zone can include flowing the emulsified carbon dioxideinto the subterranean zone through a tubular. The method can includeadding a corrosion inhibitor to the emulsified carbon dioxide to preventcorrosion of the tubular. Adding the corrosion inhibitor can includeadding the corrosion inhibitor to the second emulsion. Flowing thecarbon dioxide in the first state into the subterranean zone can enableproducing more hydrocarbons relative to flowing the carbon dioxide inthe gaseous state into the subterranean zone. A viscosity of the carbondioxide in the first state can be greater than a viscosity of the carbondioxide in the gaseous state. The density of the carbon dioxide in thefirst state can be sufficient to overcome a tendency of the carbondioxide to rise toward a surface.

In some aspects, a method of recovering of recovering hydrocarbons froma subterranean zone includes flowing a composition into the subterraneanzone including hydrocarbons. The composition includes a first emulsionof water in carbon dioxide and a second emulsion of the first emulsionin water. The method also includes recovering at least a portion of thehydrocarbons from the subterranean zone in response to flowing thecomposition into the subterranean zone.

This, and other aspects, can include one or more of the followingfeatures. Flowing the composition into the subterranean zone can includeflowing the composition through a tubular into the subterranean zone,and wherein the composition further includes a corrosion inhibitor toprevent corrosion of the tubular. The corrosion inhibitor can beincluded in the second emulsion.

In some aspects, a composition includes a first emulsion of water incarbon dioxide and a second emulsion of the first emulsion in water.

This, and other aspects, can include one or more of the followingfeatures. The first emulsion of water in carbon dioxide can bestabilized using hydrophobic nano-particles that encapsulate the water.The carbon dioxide can surround the hydrophobic particles. Thehydrophobic particles can include hydrophobic nano-particles. Aconcentration of the hydrophobic particles can be between about 0.1% and0.5% by weight. The hydrophobic particles can include at least one ofsilica or calcite having a hydrophobic nature. The second emulsion caninclude hydrophilic particles surrounding the carbon dioxide surroundingthe hydrophobic particles. The hydrophilic particles can includehydrophilic nano-particles. A concentration of the hydrophilic particlescan be between about 0.1% and 0.5% by weight. The hydrophilic particlescan include at least one of silica or calcite having a hydrophilicnature. The water can surround the hydrophilic particles.

The details of one or more implementations of the subject matterdescribed in this disclosure are set forth in the accompanying drawingsand the description below. Other features, aspects, and advantages ofthe subject matter will become apparent from the description, thedrawings, and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of example emulsified carbon dioxide forflowing into a subterranean zone.

FIG. 2 is a schematic of an example system for manufacturing theemulsified carbon dioxide.

FIG. 3 is a schematic diagram of an example subterranean formation intowhich the emulsified carbon dioxide is flowed.

FIG. 4 is a flowchart of an example process for recovering at least aportion of hydrocarbons in a subterranean zone.

Like reference numbers and designations in the various drawings indicatelike elements.

DETAILED DESCRIPTION

This disclosure relates to recovery of hydrocarbons from subterraneanzones. An enhanced oil recovery (“EOR”) technique sometimes used torecover hydrocarbons from a subterranean zone includes flowing a gassuch as carbon dioxide (CO₂) into the subterranean zone. Another exampleEOR technique is the water-alternating-gas (“WAG”) injection process. Ina WAG process, water and a gas (e.g., CO₂) are alternately injected intothe subterranean zone. The water and gas can facilitate recovery bydisplacing the hydrocarbons and improving hydrocarbon flow.

In some cases, achieving satisfactory overall recovery factor duringtertiary or EOR mode using a gas (e.g., CO₂, nitrogen or hydrocarbon)can be challenging in reservoirs containing thief zones, fractures,and/or contrasting permeability layers. A WAG process can control gassegregation during hydrocarbon recovery using gas injection. However,the overall recovery factor using this process can be less than optimumin reservoirs or containing zones with high permeability streaksincluding fractures and contrasting permeable zones. Gravity override ofthe injected gas and fluid channeling through high permeability layerscan produce poor sweep efficiency. In some cases, high amounts of gasslugs are needed during a regular WAG process. Additionally, these EORprocesses can be associated with corrosion problems that can affecttubulars and other components.

This disclosure describes a hydrocarbon recovery process that uses anemulsified gas. For example, the gas can be CO₂. In someimplementations, the emulsified gas is a fluid-gas-fluid complexemulsion. For example, the fluid can be water and the gas can be CO₂. Inother implementations, the fluid is a fluid other than water and the gasis a gas other than CO₂, such as N₂, a hydrocarbon gas, or another gas.The complex emulsion is a modified fluid/gas emulsion to enhance theperformance of EOR operations involving injection of gas. For example,the emulsified gas can be used in any tertiary process, EOR process, orWAG process that involves the injection of gas. An emulsified gas canhave higher viscosity and higher density compared to the gas in agaseous state. The higher density can reduce gas gravity override andovercome a tendency of the gas to rise toward the surface. In thismanner, use of emulsified gas can control gas mobility and mitigategravity override. The use of emulsified gas can reduce bypassedhydrocarbons (i.e., increase the ultimate hydrocarbon recovery), reducegas fingering and water channeling, improve sweep efficiency andconformance, and reduce gas utilization factors (i.e., the amount ofinjected gas). In some cases, flowing the emulsified gas into asubterranean zone enables producing more hydrocarbons relative toflowing the gas in the gaseous state into the subterranean zone.

In some implementations, corrosion inhibitors can be added in theexternal fluid layer of the complex emulsion to mitigate downholetubular corrosion. Some corrosion inhibitors are insoluble in certaingases, and thus some corrosion inhibitors cannot be added to gases(e.g., in an EOR gas injection) or emulsions in which the outer layer isgas. In this manner, the corrosion rate can be controlled through theuse of corrosion inhibitors. Furthermore, more economical and efficienthydrocarbon recovery can be achieved with less corrosion issues.

FIG. 1 is a schematic diagram of an example emulsified gas 100 forflowing into a subterranean zone. Emulsified gas 100 includes aninternal fluid-in-gas emulsion 112 that includes internal fluid 108 asan internal phase and gas 104 as an external phase. In someimplementations, the internal fluid 108 is water, and the gas 104 isCO₂. The fluid-in-gas emulsion 112 is an internal phase of thefluid-in-gas-in-fluid emulsion 100, with external fluid 102 as theexternal phase. In some implementations, the external fluid 102 iswater. The water can be distilled water, seawater, salinated water, orany other type of water. In some implementations, different types offluid can be used for the external fluid 102 and the internal fluid 108.For example, water used as external fluid 102 can be at a differentsalinity than water used as internal fluid 108.

In the fluid-in-gas emulsion 112, the outer surface of each droplet ofthe internal fluid 108 is encapsulated by multiple first particles 106.The first particles 106 can stabilize the emulsified internal fluid 108within the gas 104. The first particles 106 can be hydrophobic particles(e.g. hydrophobic nanoparticles or other hydrophobic particles), and canbe a material such as silica, calcite, or another material. The firstparticles 106 can be used in any amount sufficient to create thefluid-in-gas emulsion 112. In some implementations, the first particles106 have a concentration of 0.1-0.5 wt %. The fluid-in-gas emulsion 112,having an internal phase of fluid, can increase the density andviscosity of injected gas, thereby reducing the mobility of the gasthrough the subterranean zone. Increasing the density of injected gascan mitigate gravity override and improve the sweep efficiency of thegas injection. For example, at some reservoir conditions CO₂ viscosityis of the order 0.05 cP, compared with 1.0 cP for water and 0.8 cP foroil. This large difference in viscosities can cause unfavorablemobilities for the gas, as the gas can channel out. For example, the gascan channel horizontally for early breakthrough and channel verticallydue to density difference, leaving a significant portion of thereservoir untouched. By increasing the viscosity of the gas-carryingmedium, the gas can contact a larger portion of the subterranean zone,thus improving sweep efficiency and overall hydrocarbon recovery.

In the emulsified gas 100, the outer surface of each droplet of gas 104is encapsulated by second particles 110. The second particles 110 canstabilize the emulsified gas 104 within the external fluid 102. Thesecond particles 110 can be hydrophilic particles (e.g. hydrophilicnanoparticles or other hydrophilic particles), and can be a materialsuch as silica, calcite, or another material. The second particles 110can be used in any amount sufficient to create the emulsified gas 100.In some implementations, the second particles 110 have a concentrationof 0.1-0.5 wt %. The external fluid 102 can supply the medium for addingcorrosion inhibitors that help protect the downhole tubulars. Corrosioninhibitors can be added to the external fluid 102 and/or internal fluid108. In some implementations, additives or substances other thancorrosion inhibitors are added to the external fluid 102 and/or internalfluid 108. In this manner, the external fluid 102 can provide a mediumfor corrosion inhibitors or any other additives which are not soluble ingas.

FIG. 2 is a schematic diagram of an example system 200 to manufacture anemulsified gas. System 200 includes a cell 202 that is connected to agas supply 208 and a fluid supply 204. The cell 202 can also beconnected to a first particle supply 210, a second particle supply 212,and an additive supply 206. The system 200 can include valves, piping,tubing, seals, fasteners, or other components that facilitate operation.

As an example implementation of system 200, the system 200 can be usedto manufacture emulsified CO₂. For example, gas supply 208 can be a CO₂supply and fluid supply 204 can be a water supply. Cell 202 can beconnected to the CO₂ supply 208 and the water supply 204. Additionally,first particle supply 210 can be a hydrophobic particle supply, andsecond particle supply 212 can be a hydrophilic particle supply. Thecell 202 can also be connected to the hydrophobic particle supply 210,the hydrophilic particle supply 212, and an additive supply 206. This isan example implementation; the system can be used to manufacture othertypes of emulsified gas.

The cell 202 can be a tank, chamber, container, vat, or other enclosure.For example, cell 202 can be a hollow metal cylinder. The cell 202 canbe made of a metal such as aluminum or steel or other metal, or be madeof another material. In some implementations, the cell 202 includes ablending device 216 such as a high-shear mixer or agitator to mix thecontents of the cell 202. In some implementations, the cell 202 includesa window 214. Window 214 is a transparent window that allows theinterior of the cell 202 to be seen. In some implementations, the cell202 can control the temperature and/or pressure of the substances insidethe cell 202.

The gas supply 208 supplies the gas used in the emulsion. The gas supply208 can be a tank, vessel, chamber, Dewar, or other volume. The gassupply 208 can be integrated into the cell 202 (e.g., as an additionalchamber) or be a separate component that is connected to the cell 202(e.g., by piping). The gas supply 208 can contain gas in a pressurizedstate.

The fluid supply 204 can be a tank, vessel, chamber, well, pump, orother volume or source that can supply fluid to the cell 202. In someimplementations, the fluid supply 204 holds a specific quantity (i.e., apremeasured amount) of fluid. The fluid supply 204 can be integratedinto the cell 202 (e.g., as an additional chamber) or be a separatecomponent that is connected to the cell 202 (e.g., by piping). In someimplementations, the fluid supply 204 supplies fluid to the cell 202 ata measured rate. In some implementations, more than one fluid supply isconnected to the cell 202 to supply more than one type of fluid.

The cell 202 can be connected to a first particle supply 210 thatsupplies a first type of particles to the cell 202. The cell 202 canalso be connected to a second particle supply 212 that supplies a secondtype of particles to the cell 202. One or both of particle supplies 210,212 can be a container, vessel, chamber, port, or other component thatcan supply the particles to the cell 202. In some implementations, theparticle supplies 210, 212 hold a specific quantity (i.e., a premeasuredamount) of particles. The particle supplies 210, 212 can be integratedinto the cell 202 (e.g., as an additional chamber) or be a separatecomponent that is connected to the cell 202 (e.g., by piping). In someimplementations, the particles are added to the cell 202 before the cell202 is sealed, heated, or pressurized. In some implementations, theparticles are introduced into the cell 202 through an airlock or othertransfer chamber. In this manner, the particles can be transferred tothe cell 202 even if the cell 202 is heated or pressurized.

The additive supply 206 can be a tank, vessel, chamber, well, pump, orother volume or source that can supply additives (e.g., corrosioninhibitors or other additives) to the cell 202. In some implementations,the additive supply 206 holds a specific quantity (i.e., a premeasuredamount) of additives. The additive supply 206 can be integrated into thecell 202 (e.g., as an additional chamber) or be a separate componentthat is connected to the cell 202 (e.g., by piping). In someimplementations, the additive supply 206 supplies additives to the cell202 at a measured rate.

FIG. 3 is a diagram illustrating an example well system 300, includingan example subterranean formation 306 into which emulsified gas isflowed. The well system 200 can flow emulsified gas (e.g., emulsifiedgas 100) into a subterranean formation 306, as described below. Theexample well system 300 includes a wellbore 310 below the terraneansurface 302. In some implementations, the wellbore 310 is cased by acasing 312. A wellbore 310 can include any combination of horizontal,vertical, curved, and/or slanted sections.

The well system 300 includes a working string 316 that resides in thewellbore 310. The working string 316 terminates above the surface 302.The working string 316 can include a tubular conduit of jointed and/orcoiled tubing configured to transfer materials into and/or out of thewellbore 310. The working string 316 can be in fluid communication withan emulsion supply 320 that supplies the emulsified gas 318. Theemulsion supply 320 supplies emulsified gas 318 to the working string316 via a transfer system 322 of conduits, tubulars, pumps, piping, andother related equipment. The working string 316 can communicate a fluidsuch as the emulsified gas 318 into or through a portion of the wellbore310. In some implementations, the well system 300 includes multiplewellbores and multiple working strings.

The casing 312 can include perforations 314 in a subterranean region andthe emulsified gas 318 can flow into a formation 306 through theperforations 314. The emulsified gas 318 can be used to recoverhydrocarbons from formation 306. The emulsified gas 318 can be producedat the well system 300 site or produced off-site and transported to thewell system 300 site. In some implementations, the emulsified gas 318can be produced in a system like system 200 shown in FIG. 2. Ininstances where some or all of the wellbore 310 is left open in an “openhole configuration” coinciding with the formation 306, the emulsifiedgas 318 can flow through the open hole wall of the wellbore 310.Additionally, resources (e.g., oil, gas, and/or others) and othermaterials (e.g., sand, water, and/or others) may be extracted from theformation 306. The well system 300 can recover at least a portion of thehydrocarbons in the subterranean formation 306 in response to flowingthe emulsified gas 318 into the subterranean formation 306. The casing312 or the working string 316 can include a number of other systems andtools not illustrated in the figures.

FIG. 4 is a flowchart of an example process 400 for recovering at leasta portion of hydrocarbons in a subterranean zone. The process 400 can beimplemented, for example, by an emulsified gas such as thefluid-gas-fluid-type emulsified gas 100, the emulsified gasmanufacturing system 200, and the well system 300. At 410, a firstemulsion of fluid-in-gas is manufactured using fluid, gas, and a firsttype of particles. For example, the first emulsion can be manufacturedusing example system 200 or another system. In some implementations, thefirst emulsion is manufactured by mixing water, CO₂, and hydrophobicparticles. For example, a mixture of gas and particles can be agitatedas the internal fluid is added at a measured rate. In someimplementations, the first emulsion is manufactured at a firsttemperature and pressure. At 420, a second emulsion of the firstemulsion in fluid is manufactured. For example, the second emulsion canbe manufactured using example system 200 or another system. The secondemulsion can be an emulsified gas, for example the fluid-gas-fluidemulsion described previously. In some implementations, the secondemulsion is manufactured by mixing water, the first emulsion, andhydrophilic particles. For example, a mixture of the external fluid andparticles can be agitated as the first emulsion is added at a measuredrate. In some implementations, the second emulsion is manufactured at asecond temperature and pressure. The second temperature and pressure canbe the same or different than the first temperature and pressure. Insome implementations, corrosion inhibitors or other additives are addedto the second emulsion. In some implementations, the corrosioninhibitors or other additives are added to the fluid prior to mixingwith the first emulsion and particles. Adding corrosion inhibitor canprevent corrosion of the tubular. At 430, the second emulsion is flowedinto the subterranean zone. In some implementations, the second emulsionis flowed through a tubular into the subterranean zone. At 440, at leasta portion of the hydrocarbons in the subterranean zone are recovered inresponse to flowing the second emulsion into the subterranean zone. Insome cases, flowing the second emulsion into the subterranean zoneenables producing more hydrocarbons relative to flowing carbon dioxidein the gaseous state into the subterranean zone.

Particular implementations of the subject matter have been described.Other implementations are within the scope of the following claims.

What is claimed is:
 1. A secondary or tertiary hydrocarbon recoverymethod comprising: flowing a complex emulsion into the subterraneanzone, the complex emulsion comprising an internal fluid-in-gas emulsionconfigured to increase a density and a viscosity of a gas in theinternal fluid-in-gas emulsion emulsifying a fluid in the internalfluid-in-gas emulsion, the complex emulsion comprising an external fluidemulsifying the internal fluid-in-gas emulsion, the external fluidconfigured to carry corrosion inhibitors into the subterranean zone; andrecovering at least a portion of hydrocarbons in the subterranean zoneusing the complex emulsion flowed into the subterranean zone.
 2. Themethod of claim 1, wherein the fluid in the internal fluid-in-gasemulsion comprises water.
 3. The method of claim 2, wherein the gas inthe internal fluid-in-gas emulsion comprises at least one of carbondioxide (CO₂), nitrogen (N₂) or a hydrocarbon gas.
 4. The method ofclaim 1, wherein the complex emulsion further comprises a firstplurality of particles encapsulating an outer surface of droplets of thefluid in the internal fluid-in-gas emulsion.
 5. The method of claim 4,wherein the first plurality of particles comprise hydrophobic particles.6. The method of claim 4, wherein the first plurality of particlescomprise at least one of hydrophobic silica or hydrophobic calcite. 7.The method of claim 5, wherein a concentration of the first plurality ofparticles is between about 0.1% and 0.5% by weight.
 8. The method ofclaim 1, wherein the complex emulsion comprises a second plurality ofparticles encapsulating an outer surface of droplets of the externalfluid.
 9. The method of claim 8, wherein the second plurality ofparticles comprise hydrophilic particles.
 10. The method of claim 8,wherein the second plurality of particles comprise at least one ofhydrophilic silica or hydrophilic calcite.
 11. The method of claim 8,wherein a concentration of the second plurality of particles is betweenabout 0.1% and 0.5% by weight.
 12. The method of claim 1, wherein thecomplex emulsion further comprises corrosion inhibitors added to theexternal fluid.
 13. The method of claim 1, wherein the complex emulsionis flowed into the subterranean zone in a secondary, tertiary orenhanced hydrocarbon recovery operation after a primary hydrocarbonrecovery operation.
 14. A secondary or tertiary hydrocarbon recoverymethod comprising: manufacturing a complex emulsion comprising aninternal fluid-in-gas emulsion configured to increase a density and aviscosity of a gas in the internal fluid-in-gas emulsion emulsifying afluid in the internal fluid-in-gas emulsion, the complex emulsioncomprising an external fluid emulsifying the internal fluid-in-gasemulsion, the external fluid configured to carry corrosion inhibitorsinto the subterranean zone; flowing the complex emulsion into thesubterranean zone; and recovering at least a portion of hydrocarbons inthe subterranean zone using the complex emulsion flowed into thesubterranean zone.
 15. The method of claim 14, wherein manufacturing thecomplex emulsion comprises mixing the gas in the internal fluid-in-gasemulsion, the fluid in the internal fluid-in-gas emulsion and theexternal fluid in a tank under controlled temperature and pressure. 16.The method of claim 15, wherein the complex emulsion further comprises afirst plurality of particles encapsulating an outer surface of dropletsof the fluid in the internal fluid-in-gas emulsion and a secondplurality of particles encapsulating an outer surface of droplets of theexternal fluid, wherein manufacturing the complex emulsion comprisesmixing the first plurality of particles and the second plurality ofparticles with the gas in the internal fluid-in-gas emulsion, the fluidin the internal fluid-in-gas emulsion and the external fluid in thetank.
 17. The method of claim 16, wherein the first plurality ofparticles and the second plurality of particles are added to the tankafter mixing the gas in the internal fluid-in-gas emulsion, the fluid inthe internal fluid-in-gas emulsion and the external fluid.
 18. Themethod of claim 15, wherein manufacturing the complex emulsion comprisesfirst manufacturing the internal fluid-in-gas emulsion and thenmanufacturing the complex emulsion as an emulsion of the internalfluid-in-gas emulsion in the external fluid.
 19. A complex emulsion forsecondary or tertiary hydrocarbon recovery from a subterranean zone, thecomplex emulsion comprising: an internal fluid-in-gas emulsionconfigured to increase a density and a viscosity of a gas in theinternal fluid-in-gas emulsion emulsifying a fluid in the internalfluid-in-gas emulsion; and an external fluid emulsifying the internalfluid-in-gas emulsion, the external fluid configured to carry corrosioninhibitors into the subterranean zone.
 20. The complex emulsion of claim19, further comprising: a first plurality of hydrophobic nanoparticlesencapsulating an outer surface of droplets of the fluid in the internalfluid-in-gas emulsion; and a second plurality of hydrophilic particlesencapsulating an outer surface of droplets of the external fluid.